Wellbore packer, method and tubing string

ABSTRACT

A wellbore packer for setting one or more packing elements in a borehole having an open hole section. The wellbore packer comprises a port-less mandrel configured with one or more packing elements and one or more setting mechanisms. The setting mechanism is responsive to a driving force and configured to set the packing elements in the borehole, wherein the driving force is not tubing string pressure. Where packers are set by annular pressure, a method for setting a plurality of such packers may include sequentially operating the packers. A mechanism may be provided for the packers to allow sequential operation thereof.

FIELD OF THE INVENTION

The invention relates to a tool, method and string for wellboreoperations and, in particular, a packer, a tubing string and apacker-setting method for a wellbore.

BACKGROUND OF THE INVENTION

In wellbore operations, packers may be used to control migration offluids outside a tubing string such as a liner or other casing installedin the wellbore. For example, packers may be installed in the annulusbetween the tubing string and the wellbore wall to deter migration ofthe fluids axially along the annulus.

Packers may be actuated and/or set by application of hydraulic pressure.Oftentimes, the hydraulic pressure is introduced through the tubularstring on which the packer is installed and is communicated to thepacker's hydraulically actuated system by a port through the tubularwall, also called a mandrel, on which the packing elements areinstalled. The port extends through the tubular wall and providescommunication from the tubing string inner diameter and the hydrauliccylinder for the packer. There are seals within the cylinder thatcontains the hydraulic pressure so that the pressure biases the cylinderto set the packer.

One of the disadvantages of hydraulically set mechanical packers is theport in the tubular wall. In pressuring applications, for example, whenfracing a well and/or pressurizing the liner, the hydraulic cylindersare subjected to the pressures being utilized and in some cases, emptycyclic pressures, which results in cylinders moving and seals movingunder pressure situations, which can be greater than 10,000 psi and atelevated temperatures. Under such conditions, the ports in the tubingstring that open to the packer setting chambers introduce a point ofweakness and potential failure. Additionally, in high temperatureapplications, seals, and the like, can degrade, and a leak path can formthrough the port in the mandrel and into the annulus, past theproblematic seals.

Accordingly, there remains a need for improvements in the art.

BRIEF SUMMARY OF THE INVENTION

In accordance with a broad aspect of the present invention, there isprovided a wellbore packer with a port-less mandrel.

In accordance with another broad aspect, there is provided a method forinstalling a packer to create a seal in a wellbore defined by a wellborewall, the method comprising: running the packer into a wellbore, thepacker installed along a tubing string and including a packing elementand a setting mechanism for the packing element; positioning the packerin the wellbore adjacent an open hole section of the wellbore wall tocreate an annular area between the packer and the wellbore wall; settingthe packer while isolating tubing string pressure from the packersetting mechanism and while maintaining hydrostatic pressure in theannular area; and allowing the packing element to expand to create aseal in the annular area between the tubing string and the open holesection of the wellbore wall.

According to another embodiment there is provided a wellboreinstallation in a wellbore comprising: a tubing string including a fracport; a wellbore packer connected into the tubing string and forming anannular seal in the wellbore separating a first annular area accessedthrough the frac port from a second annular area, the wellbore packerincluding: a port-less mandrel having a longitudinal axis; a packingelement coupled to said mandrel; a setting mechanism coupled to saidport-less mandrel including a piston configured with a compressing ringproximate one end of the packing element, and a stop ring proximateanother end of said packing element, said stop ring being affixed tosaid mandrel and configured to block movement of said packing element;the setting mechanism configured to be responsive to a driving force todrive the piston in a first direction along said longitudinal axis tomove said compressing ring against said one end of said packing elementand compress said packing element against said stop ring so that saidpacking element is compressed and expands outwardly from said port-lessmandrel to form the seal in the wellbore; and a port for communicatingfluid from the first annular area to the piston.

According to another embodiment, there is provided a wellbore packer forcreating a seal in a borehole, said wellbore packer comprising: aport-less mandrel having a longitudinal axis; first and second packingelements coupled to said mandrel in a spaced relationship along saidlongitudinal axis; a first piston configured with a first compressingring proximate one end of said first packing element, and a first stopring proximate another end of said first packing element, said firststop ring being affixed to said mandrel and configured to block movementof said first packing element; a second piston configured with a secondcompressing ring proximate one end of said second element, and a secondstop ring proximate another end of said second packing element, saidsecond stop ring being affixed to said mandrel and configured to blockmovement of said second packing element; a drive mechanism coupled tosaid port-less mandrel and configured to drive said first piston in afirst direction along said longitudinal axis to move said firstcompressing ring against said one end of said first packing element andcompress said first packing element against said first stop ring so thatsaid packing element is compressed and expands outwardly from saidmandrel to form a seal in the borehole; and said drive mechanism beingconfigured to drive said second piston in a second direction along saidlongitudinal axis opposite said first direction and move said secondcompressing ring against said one end of said second packing element andcompress said second packing element against said second stop ring sothat said packing element is compressed and expands outwardly from saidmandrel to form a seal in the borehole.

According to another aspect of the invention, there is provided a methodfor setting a plurality of packers on a wellbore string, the methodcomprising: operating a first wellbore packer by exposing a mechanism ofthe first wellbore packer to annular pressure; and delaying the settingof a second wellbore packer that is axially spaced along the wellborestring from the first wellbore packer until after operating the firstwellbore packer.

According to another aspect of the invention, there is provided anapparatus for fluid treatment in a wellbore, the apparatus comprising: atubing string having a long axis and including a wall portion definingan inner bore therein; a first packer operable to seal about the tubingstring and mounted on the tubing string; a second packer operable toseal about the tubing string and mounted on the tubing string in aposition axially offset along the tubing string from the first packer;and a packer setting mechanism for selectively operating sequentiallythe first packer and the second packer toward setting.

According to another aspect of the invention, there is provided a methodfor securing a tubing string in a wellbore, the method comprising:running a tubing string into the wellbore, wherein the tubing stringincludes a long axis, a wall portion defining an inner bore; a firstpacker operable to seal about the tubing string and mounted on thetubing string; a second packer operable to seal about the tubing stringand mounted on the tubing string in a position axially offset along thetubing string from the first packer; positioning the tubing string inthe wellbore forming an annulus between the tubing string and a wall ofthe wellbore; and selectively operating the first packer and the secondpacker sequentially by application of annular fluid pressure.

It is to be understood that other aspects of the present invention willbecome readily apparent to those skilled in the art from the followingdetailed description, wherein various embodiments of the invention areshown and described by way of illustration. As will be realized, theinvention is capable for other and different embodiments and its severaldetails are capable of modification in various other respects, allwithout departing from the spirit and scope of the present invention.Accordingly the drawings and detailed description are to be regarded asillustrative in nature and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

Referring to the drawings, several aspects of the present invention areillustrated by way of example, and not by way of limitation, in detailin the figures, wherein:

FIG. 1 is a sectional view through a wellbore packer according to anembodiment of the present invention;

FIGS. 2(a) to 2(f) illustrate operation of a magnetic switch to set apacker in accordance with an embodiment of the present invention.

FIGS. 3(a) to 3(d) illustrate a method according to an embodiment of thepresent invention.

FIG. 4 illustrates another method according to an embodiment of thepresent invention.

In the drawings, like reference numerals indicate like elements.

DETAILED DESCRIPTION OF THE EMBODIMENTS

The description that follows and the embodiments described therein areprovided by way of illustration of an example, or examples, ofparticular embodiments of the principles of various aspects of thepresent invention. These examples are provided for the purposes ofexplanation, and not of limitation, of those principles and of theinvention in its various aspects. In the description, similar parts aremarked throughout the specification and the drawings with the samerespective reference numerals. The drawings are not necessarily to scaleand in some instances proportions may have been exaggerated in ordermore clearly to depict certain features.

The present application discloses a packer that is set by hydraulicconditions in the annulus and a wellbore string and methods in thisregard. In one embodiment, a packer is disclosed that does not require athrough-mandrel setting port, i.e. a port or opening through which fluidcommunicates outwardly from the mandrel inner diameter (ID). Accordingto an embodiment, the packer is set using a hydraulic configurationresponsive to annular hydrostatic pressure, for example, in oneembodiment as described in more detail below. According to one aspect,the packer mandrel comprises a port-less, end-to-end steel tubular withall moving parts on the outside of the packer. It will be appreciatedthat one advantage of not having a port in the mandrel is that apossible leak point is avoided. For example, when a tubing stringcarrying a no-port packer is pressurized, for example, during fracturingoperations or the like, the packer and/or the setting cylinder are notsubjected to the pressurization, which decreases the likelihood of apressure-based breach in the mandrel. As described in more detail below,the hydraulic arrangement provides a mechanism for activating the packerin a position in the wellbore without requiring pressurization of thetubing string inner diameter on which the packer is carried and withoutcommunication of that inner diameter pressure through the wall of thepacker mandrel to the packer setting mechanism. Stated another way, themechanism for setting the packer may be operated in response to annularpressure without communicating tubing string pressure through themandrel wall. In one embodiment, for example, the packer may betriggered and driven to set while the normal, natural tubing stringpressure for that depth (hydrostatic pressure) is maintained in thetubing string.

For example, a method is taught for installing a packer to create a sealin a wellbore defined by a wellbore wall, the method comprising: runningthe packer into a wellbore, the packer installed in a tubing string andincluding a mandrel, a packing element encircling the mandrel and asetting mechanism for the packing element; positioning the packer in thewellbore adjacent an open hole section of the wellbore wall to create anannular area between the packer and the wellbore wall; setting thepacker while preventing tubing string pressure from passing through themandrel to the packer setting mechanism and while maintaining at leasthydrostatic pressure in the annular area; and allowing the packingelement to expand to create a seal in the annular area between thetubing string and the open hole section of the wellbore wall.

In the method, preventing may include selecting the packer to have nopacker setting port through the mandrel such that pressure cannot becommunicated from the tubing string to the setting mechanism; settingmay include applying a compressive setting force to the packing elementand/or setting may occur after a timer expires.

The method may further comprise increasing pressure in the annulus totreat the wellbore and increasing pressure may include increasing asetting force applied to the packing element and/or triggering thepacker to set and there may be a time delay between triggering andsetting.

The method may employ a configuration wherein a second packer is carriedon the tubing string and is axially spaced along the tubing string fromthe packer and prior to setting, the second packer is operated inresponse to annular pressure. Alternately or in addition, positioningmay position the second packer uphole from the packer and setting mayoccur before the second packer is set or positioning may position thesecond packer downhole from the packer and setting occurs before thesecond packer is set.

Additionally, a wellbore installation for a wellbore is taughtcomprising: a tubing string including a frac port; and a wellbore packerconnected into the tubing string and forming an annular seal in thewellbore separating a first annular area accessed through the frac portfrom a second annular area, the wellbore packer including: a port-lessmandrel having a longitudinal axis; a packing element encircling saidmandrel; a setting mechanism coupled to said port-less mandrel includinga piston configured with a compressing ring proximate one end of thepacking element, and a stop ring proximate another end of said packingelement, said stop ring being affixed to said mandrel and configured toblock movement of said packing element, the setting mechanism configuredto be responsive to a driving force to drive the piston in a firstdirection along said longitudinal axis to move said compressing ringagainst said one end of said packing element and compress said packingelement against said stop ring so that said packing element iscompressed and expands outwardly from said port-less mandrel to form theseal in the wellbore; and a port for communicating fluid from the firstannular area to the piston.

Additionally, a wellbore packer is taught for creating a seal in aborehole. The wellbore packer may include: a port-less mandrel having alongitudinal axis; first and second packing elements encircling saidmandrel in a spaced relationship along said longitudinal axis; a firstpiston configured with a first compressing ring proximate one end ofsaid first packing element, and a first stop ring proximate another endof said first packing element, said first stop ring being affixed tosaid mandrel and configured to block movement of said first packingelement; a second piston configured with a second compressing ringproximate one end of said second element, and a second stop ringproximate another end of said second packing element, said second stopring being affixed to said mandrel and configured to block movement ofsaid second packing element; a drive mechanism coupled to said port-lessmandrel and configured to drive said first piston in a first directionalong said longitudinal axis to move said first compressing ring againstsaid one end of said first packing element and compress said firstpacking element against said first stop ring so that said packingelement is compressed and expands outwardly from said mandrel to form aseal in the borehole; and said drive mechanism being configured to drivesaid second piston in a second direction along said longitudinal axisopposite said first direction and move said second compressing ringagainst said one end of said second packing element and compress saidsecond packing element against said second stop ring so that saidpacking element is compressed and expands outwardly from said mandrel toform a seal in the borehole.

The packer may further include a locking mechanism comprising a lockingratchet, said first piston being configured with a reciprocal ratchetfor engaging said locking ratchet, said second piston being configuredwith a reciprocal ratchet for engaging said locking ratchet, and saidlocking ratchet being configured to prevent bi-directional movement ofsaid first and said second pistons. The first piston may comprise apiston skirt and the second piston may comprise a piston skirt having anexterior surface, and the piston skirt of said first piston may bepositioned around the exterior surface of the piston skirt of saidsecond piston and configured in an overlapping and telescopingarrangement. The borehole in which the packer is to be used comprises anopen hole section, and the wellbore packer may be configured to set thepacking elements in said open hole section.

Methods are also taught for setting the one or more packing elements inan open hole section of a borehole.

In one embodiment, the packer includes a packing element that, whentriggered, sets to create a seal in the annulus about the string, whichincludes the mandrel on which the packing element is carried. Whensetting, the packing element expands radially outward to fill the spacebetween the liner and the wellbore wall, which may be casing in a casedhole or exposed formation in an open hole. The packing element may beset by a setting mechanism that operates by mechanical compression or byswelling.

In an embodiment where the packing element is set by mechanicalcompression, the compression may be by stroking of a setting mechanism.Stroking of the setting mechanism applies a force against the packingelement such that the packing element is axially compressed and itextrudes outwardly. Where the packing element is set by swelling, asetting mechanism may expose the swellable element to fluid that causesit to expand. In one embodiment, the swellable element is normallyisolated, as by a covering, from a hydraulic fluid that causes swellingof the packing element, and when the packer is triggered, the packingelement that is swellable is exposed to that fluid so that swellingbegins. The setting mechanism for a swellable packer may include astroking mechanism, a burst mechanism, etc.

The setting mechanism is responsive to a driver. For example, strokingof a setting mechanism could be by any of various drivers includingfluid pressure drives, electrical drives, biasing members, etc. A fluidpressure drive may be due to any of various pressurizing events such as(i) by total wellbore pressure, which is the normal annular pressure fora well depth (hydrostatic), (ii) by increasing pressure in the annulus,(iii) by release of pressurized fluid such as from a nitrogen charge,(iv) by a fluid producing event (primer cord), etc. An electrical drivemay be generated by a motor powered by a battery or an electricalconductor.

Some packers set when exposed to the driver. Other packers set only whenactivated to do so by a triggering mechanism. In such embodiments, thetriggering mechanism causes the driver to move the setting mechanism. Atriggering mechanism can include one or more of various mechanisms.Since a packer is intended to create a seal in a wellbore, thetriggering mechanism may be selected to be activated when the packer ispositioned downhole. As such, the triggering mechanism may be responsiveto downhole conditions, to only cause the packer to set when thetriggering mechanism arrives downhole, and/or the triggering mechanismmay be responsive to a signal initiated from surface to only allowsetting when a signal is communicated from surface and received by thetriggering mechanism and/or the triggering mechanism may only cause thepacker to set when an appropriate time has lapsed, for example, to onlyallow the packer to set when time has passed sufficient to ensure thatthe packer is downhole.

According to one embodiment, for example, the packer includes a settingmechanism responsive to a pressure driver of annular pressure, forexample, annular hydrostatic pressure. The setting mechanism isconfigurable to be released and driven by the pressure drive and, forexample, may include a stroking mechanism including a low pressure, forexample atmospheric, chamber and a hydraulic chamber that can be exposedto a pressure drive to act against the atmospheric chamber. The strokingmechanism can be part of a hydraulic cylinder that acts against theatmospheric chamber, as driven by the pressure drive and, whenactivated, can compress the packing element conventionally like amechanically activated packer. In such an embodiment, the packingelement, setting mechanism and driver may be installed on the outside ofthe mandrel. The packer further includes a triggering mechanism that isactivated to expose the hydraulic pressure chamber to the pressuredrive. Thus, the setting mechanism is released and driven by the driver,when the triggering mechanism is activated to set the packing element.

Reference is first made to FIG. 1, which shows a wellbore packeraccording to one embodiment and indicated generally by reference 100.The wellbore packer 100 comprises a mandrel 110, one or more packingelements (here two are shown indicated individually by references 120 aand 120 b), a hydraulically driven setting mechanism 130 and amechanical body lock 140.

In use, the mandrel 110 is connected at its ends into a tubing string111 and positioned in a borehole. According to an embodiment, theborehole comprises an open hole section such that at least wellbore wall112 adjacent the packer is open hole, uncased, with the formationexposed. An annulus 113 is formed between the packer and wall 112.

The mandrel 110 comprises a tubular wall defining therein an innerdiameter ID. According to an embodiment, the mandrel 110 comprises aport-less configuration, i.e. the mandrel does not include a portthrough its wall thickness in communication with the inner diameter forproviding a pressurization path to the packer. Wellbore packer 100 isset using a driver other than direct communication through a mandrelport of the tubing string inner diameter ID pressure to the settingmechanism. As will be described in more detail below, the illustratedwellbore packer 100 is set using a pressurized fluid, but without therequirement for pressure communication from the inner diameter IDthrough the mandrel 110 to the packer setting mechanism.

The packing elements 120 a, 120 b comprise extrudable packing elements.According to an exemplary implementation, the packing elements 120 a,120 b are annular and formed of an elastomer, for example, rubber.According to another aspect, the packing elements 120 a, 120 b comprisean enlarged cross section in the set position (for example, as depictedin FIG. 2(f)) and the increased expansion ratio allows the packingelements 120 a, 120 b to be set in oversized holes.

As shown in FIG. 1, the packing element 120 a is mounted between a fixedstop ring 150 a and a compressing ring 152 a. Similarly, the secondpacking element 120 b is mounted on the mandrel 110 between a fixed stopring 150 b and a compressing ring 152 b. According to an exemplaryimplementation, the hydraulically actuated setting mechanism 130comprises a port 142 which provides fluid access from a nitrogen charge144 to a hydraulic chamber 146 which is defined between a first piston160 and a second piston 162. The hydraulically actuated settingmechanism 130 is configured with a triggering mechanism indicatedgenerally by reference 148. In operation, the nitrogen charge 144comprises nitrogen under pressure which is released in response toactivation by the triggering mechanism 148 to create a pressure drive.

In operation, actuation of the triggering mechanism 148 results in arelease of nitrogen from the nitrogen charge 144 which generates fluidpressure in chamber 146, which drives the first piston 160 against thefirst compressing ring 152 a and compresses the first packing element120 a against the first fixed stop ring 150 a. The compression of thepacking element 120 a causes outward expansion. Similarly, actuation ofthe triggering mechanism 148 drives the second piston 162 against thesecond compressing ring 152 b and compresses the second packing element120 b against the second fixed stop ring 150 b. The compression of thepacking element 120 b causes outward expansion to create a seal in thewellbore.

According to an embodiment, the first piston 160 includes a skirt 163,which encloses the hydraulic chamber between the two pistons 160 and 162and is configured to telescopically ride over the second piston 162.According to another aspect, the wellbore packer 100 includes seals 170which are configured to prevent leakage of fluid between the pistonassemblies and into chamber 146.

According to an embodiment, the mechanical body lock system 140comprises a ratchet mechanism as shown in FIG. 1. The ratchet mechanism140 is configured between the skirt 163 of the first piston 160 and thesecond piston 162 and permits the pistons 160, 162 to move away fromeach other, i.e. in response to fluid pressure of the released nitrogencharge resulting in the compression of the respective packing elements120, but prevents the pistons 160, 162 from moving back towards eachother, i.e. back into the initial positions. According to an exemplaryimplementation, each of the pistons 160, 162 includes a reciprocalratchet or latch that engage in the ratchet mechanism 140 to preventreverse movement of the pistons. By preventing reverse movement of thepistons 160, 162, the ratchet mechanism 140 effectively locks thepacking elements 120 a, 120 b into a compressed, expanded configuration.

As shown in FIG. 1, the fixed stop ring 150 a can include shearsindicated generally by reference 172. The shears 172 are configured tomount or affix the fixed stop ring 150 a to the mandrel 110. Accordingto another aspect, the shears 172 are configured to shear or break, forexample, when the tubing string is pulled up, this releases the fixedstop ring 150 a which in turn releases the compressive force on thepacking elements 120 a, 120 b.

Triggering mechanism 148, that causes setting mechanism 130 to stroke,can include one or more of various mechanisms. For example, it isgenerally desired that the triggering mechanism may be selected to allowthe packer to stroke only when the packer is positioned downhole. Thus,the triggering mechanism (i) may be responsive to downhole conditions,to only set when it arrives downhole, and/or (ii) may be timed to setonly when a particular time has passed, that time being sufficient toensure that the packer is downhole and/or (iii) may be responsive to asignal, for example, initiated from surface to only allow stroking whenthe signal is communicated from surface.

As an example of a triggering mechanism activated by signaling fromsurface, one embodiment employs a stroking mechanism triggered bypressuring up the annulus. For example, the stroking mechanism may besecured by a shear that can be overcome at a particular pressure. Theparticular pressure may be, for example, above hydrostatic conditions(so the packer is not driven to set by simply running into the hole) butbelow fracing pressures, such that the formation is not broken down(i.e. fraced) by setting the packer. In particular, normally when apacker is run there is fluid or drilling mud in the hole, the weight ofwhich can be determined. Therefore, it is possible to calculate theheight or static pressure of the mud or fluid column in the annulus.This pressure is determined by how much height or static pressure isrequired to maintain control of the well, including control of thepressure of the gas or hydrocarbons in the well. A packer installed in awell can be run that has a pressure activated setting cylinder set toactivate at a particular pressure, which is higher than the pressuregenerated by the height or static pressure of the mud. Therefore, as thepackers are run on the string into the well and after they arepositioned, they remain in the unset position. However, when the packersare properly positioned and it is appropriate to set them, pressure isapplied through the annulus up to fracturing pressure, which may beseveral thousand PSI higher than the hydrostatic pressure created by themud weight. So, the setting cylinder can be set to trigger and stroke ata pressure somewhere between the hydrostatic pressure of the mud and thefracturing pressure of the formation.

Once the packers are in the correct position in the well, the particularpressure may be achieved by “pressuring up” the annulus, as byadjustment from surface. In particular, pressure could be applied to theannulus between the tubing string and the wellbore wall in communicationwith the packer.

In such an embodiment, the increased annular pressure may be employed asthe triggering mechanism, but may also be employed as the driver. Forexample, the annular fluid may be communicated to a piston and apressure differential could be generated against an atmospheric chamberin the stroking mechanism to drive compression of the packing element.Alternately, the pressuring up can simply trigger the packer operation,for example, permit operation of the setting mechanism and, thereafter,the pressure can be dissipated before a driver, such as hydrostaticpressure, is employed to actually set the packer.

When annular pressure (i.e. hydrostatic, pressure pulses, orpressured-up conditions) is employed to operate, such as to trigger orto set, a packer, it may be important to ensure that the annularpressure is able to be properly and reliably communicated to thatpacker. For example, if annular pressure is employed to operate aplurality of packers on a string in a wellbore, premature setting andpressure isolation, caused by setting of one of the plurality of packersbefore another of the plurality of packers can adversely impact theinstallation of the string and the wellbore methods.

Setting of a packer radially expands the packer element to create a sealin the annulus. This packer-established seal is intended to seal againstpressure and fluid communication through the annulus and, thus, canisolate operative annular pressure from another packer.

For example, consider a simple example of two spaced apart packers,including an uphole packer and a downhole packer below the upholepacker, in a well. If hydrostatic pressure is employed to operate thetwo spaced apart packers, setting of the uphole packer before thedownhole packer can set, can modify, for example reduce, the hydrostaticpressure at the downhole packer such that it may fail to set. The samecan be true if the packers are set by an annular-fluid-conveyed signal,such as for example, pressurization or a pressure pulse. If the twopackers rely on the annular-fluid-conveyed signal from a source and oneof the packers sets between the source of the signal and the otherpacker, the signal can be isolated from ever reaching the other packer.Therefore, according to an aspect of the invention, a packer mechanismmay be employed to ensure that the two spaced apart packers are pressureoperated sequentially (i.e. one after another). The packer mechanism maytake various forms and may include one mechanism for each packer or acomponent that serves both. The mechanism may include any of mechanical,electrical, electronic and/or software components. The sequential orderof the packer operation may be selected depending on the source of theannular pressure activation. For example: (i) if the packers areoperated (i.e. triggered or set) by hydrostatic pressure, the packersmay be operated sequentially starting with the lowest (most downhole)packer along the string and the setting may move up from there; (ii) ifthe packers are operated (i.e. triggered or set) by anannular-fluid-conveyed signal from surface conveyed down through theannulus, the packers may each have a mechanism to ensure sequentialsetting starting with the lowest (most downhole) packer along the stringand the setting operations may move up from there; or (iii) if thepackers are operated (i.e. triggered or set) by anannular-fluid-conveyed signal conveyed from below and which comes upthrough the annulus, the packers may each have a mechanism to ensuresequential operation starting with the most uphole packer (i.e. the oneclosest to surface) and the annular pressure driven operation may movedown from there from packer to packer. It will be appreciated that if itis the triggering that requires exposure to annular pressure, but theactual setting does not, then in the sequential operation, a secondpacker may be set to isolate the first packer before the first packer isactually set, provided sufficient time is provided for exposure of thefirst packer to annular pressure for triggering thereof.

In a method for setting a plurality of packers on a wellbore string, themethod may comprise: operating a first wellbore packer by exposing anoperating mechanism of the first wellbore packer to annular pressure;and delaying the setting of a second wellbore packer that is axiallyspaced from the first wellbore packer until after the first wellborepacker is operated. Thus, the packers are operated sequentially byannular pressure wherein the first wellbore packer is operated first andthen the second wellbore packer is operated to set.

Thus, with reference to FIGS. 3(a) to 3(d), a wellbore string 311 maycarry a plurality of wellbore packers 300 a, 300 b, 300 c that areoperated, for example triggered to set or set, in response to wellboreannular pressure. On such a string, packers 300 a, 300 b and 300 c areaxially offset from each other along the string. Some packers aredownhole of other packers, for example, packer 300 a is the lower-mostpacker being downhole of packer 300 b and packer 300 c and packer 300 cis closest to surface, with packers 300 b and 300 a downhole thereof.

The string may include other tools such as a liner hanger 396, wellboretreatment ports 398 and/or a toe sub 399.

The string is positioned (FIG. 3(a)) in a well 312 while the packersremain unset. An annulus 313 is formed, which is the space between thestring and the wellbore wall.

If the string inner diameter is not already pressure isolated, forexample, if toe sub 399 was open for circulation during run in, toe sub399 may be closed.

A method for setting the plurality of annular pressure responsivepackers 300 a, 300 b, 300 c on wellbore string 311, may include delayingthe setting of the upper packers until the lowermost packer'spressure-responsive operation is carried out by annular pressure. Thispacker operation may be triggering and/or setting the packer. Thus, forexample as illustrated in FIG. 3(b), triggering and/or setting a firstwellbore packer, such as lowermost packer 300 a, by exposing amechanism, such as a triggering mechanism or setting mechanism, of thefirst wellbore packer to annular pressure P proceeds ahead of thesetting of a second wellbore packer, such as packer 300 b, that isuphole from the first wellbore packer.

If there is more than one packer above the lowermost annular pressureset packer, such as is illustrated here, the setting of all packersabove the lowermost packer should be delayed until any operation thatrequires annular pressure is completed for packer 300 a.

In the same way, if packer 300 b, which is below packer 300 c requireshydrostatic pressure or annular pressure signaling for its operation,packer 300 c is delayed from setting, and thereby sealing annulus 313,until packer 300 b is operated by annular pressure FIG. 3(c).

Finally, as shown in FIG. 3(d) the uppermost packer 300 c can be set tocreate another isolated annular region 313 b in the wellbore.

If liner hanger 396 has a packer component, the setting of uppermostpacker 300 c creates another isolated annular region 313 c.

Annular pressure set packers may be biased towards the pressure source.Since packers 300 a to 300 c are set by pressure from above, thepressure-responsive operating mechanism, such as a pressure responsivechamber, may face uphole toward surface so that pressure from above canaccess it, even if the packer is already partially set.

As may be noted, a liner hanger such as liner hanger 396 is employed tosecurely hold the liner in the well and may include an anchoringmechanism, such as slips, to expand out and engage the surrounding wall(casing C, as shown, or the wellbore wall) at the location where theliner hanger is positioned. Additionally, liner hanger 396 may include apacker for well control, to isolate annular pressure below the linerhanger from conditions above. Thus, since the packers 300 a to 300 c areset from annular pressure above, if liner hanger 396 includes a packer,it may be necessary to consider the liner hanger operation in theabove-noted method.

In one embodiment, therefore, string 311 may be held in place withoutsetting liner hanger until packers 300 a to 300 c are set. In such anembodiment, a work string, for example, may be employed to hold string311. As such liner 311 is held steady during the packer settingoperations. The liner hanger may be set last.

In another embodiment, at least the packer portion of the liner hangeris not set until the packers in the annulus below are operated byannular pressure. Thus, the annular pressure remains live to the packersbelow the liner hanger and the packers can be set. Thereafter, the linerhanger packer may be set to finally seal the annulus at the upper end ofliner 311. In such an embodiment, the slip portion of the liner hangermay be set first before the packers are set or the whole string may beheld simply by a work string. Either way, the liner 311 is held steadyduring the packer setting operations. If the slips are set first, a sliparrangement can be used that allows fluid communication therepast. Sucha method allows the work string to be pulled out of the hole after theanchoring mechanism is set.

Alternately, in another embodiment, the packer of the liner hanger canbe set to create a seal in the annulus. This will close off the annulus313 below liner hanger 396 to pressure from above. In such anembodiment, a communication port 397 can be provided below (downhole of)the seal of the liner hanger. After installation of the liner andsetting of liner hanger, port 397 can be opened (FIG. 3(b)) to provideaccess from the inner diameter of the string to annulus 313 such thatpressure can be communicated to the packers 300 a to 330 c. Then thepacker setting operation for packers 300 a to 300 c, as noted above, canproceed. Once the packers are set, the communication port 397 can beclosed. This method, whereby the liner hanger packer is set beforeinitiating the packer setting operations, allows the work string to bepulled out of the well before setting the packers and ensures that thewell is secured at an early stage in the wellbore operations: beforeinitiating other wellbore operations.

FIG. 4 shows another wellbore string 411 that carries a plurality ofwellbore packers 400 a, 400 b, 400 c. Packers 400 a, 400 b and 400 c areaxially offset from each other along the string. Some packers aredownhole of other packers, for example, packer 400 a is the lower-mostpacker being downhole of packer 400 b and packer 400 c and packer 400 cis the most uphole packer, being closest to surface with packers 400 band 400 a downhole thereof.

The string may include other tools such as wellbore treatment ports 498,a liner hanger and/or a toe sub 414. To facilitate illustration, packer400 a may be considered an independent packer or a packer of a linerhanger.

The string is positioned in a well 412. An annulus 413 is formed betweenthe string and the wellbore wall.

In this embodiment, packers 400 a, 400 b, 400 c are operated (triggeredor set) in response to wellbore annular pressure and wellbore annularpressure is adjusted by pressure communication through the strings innerdiameter ID, which opens to annulus 413 at an opening such as a port intoe sub 414 at the toe 411 a of the string. For example, as shown byarrows F1, a pressure increase in the annulus may be caused, and/or afluid conveyed signal may be transmitted, via the fluid in the string'sinner diameter, through the port in toe 411 a and then through annulus413 to the packers. Thus, the pressure source for annular-pressureoperation of the packers is the toe 411 a of the string.

A method for setting the plurality of annular pressure responsivepackers 400 a, 400 b, 400 c on wellbore string 411 may includepreventing the lower packers from setting until the upper packer'sannular-pressure responsive operation is carried out by annularpressure. This packer operation may be triggering and/or setting thepacker. Thus, triggering and/or setting a first wellbore packer, such asuppermost packer 400 c (shown already set), by exposing a mechanism,such as a triggering mechanism or setting mechanism, of that wellborepacker to pressure F1 in the annulus proceeds ahead of the setting of asecond wellbore packer, such as packer 400 a and/or packer 400 b, thatis downhole from the uppermost wellbore packer 400 c.

The uppermost packer 400 c, even if it is a liner hanger packer, may beset first. In one embodiment, it may be desirable to independently setthe liner hanger to ensure the well is secured. Thus, while theuppermost packer 400 c is herein disclosed as being annular pressureoperated, the liner hanger packer may not be annular set and/or may beset apart from the packer sequencing method.

It will be appreciated that if any of the packers below the uppermostpacker set before the uppermost packer is able to respond to annularpressure, those lower packers can isolate and prevent the properoperation of the uppermost packer. Thus, if there is more than onepacker below the uppermost annular pressure set packer, such as isillustrated here, the setting of all packers below the uppermost packershould be delayed until any operation that requires annular pressure iscompleted for packer 400 c.

In the same way, therefore, if packer 400 b, which is above packer 400a, requires annular pressure signaling for its operation, packer 400 ais delayed from setting, and thereby sealing annulus 413, until packer400 b is operated by annular pressure.

Finally, the lowermost packer 400 a can be set to create anotherisolated annular region 413 b in the wellbore.

The pressure communication to packers 400 a to 400 c is provided throughthe toe sub. When the packers are finally pressure operated, the toe sub414 may be closed to prevent flow into or out of the liner at thatpoint. Thus, in one embodiment, the sequencing operation for setting thepackers may be followed by closing the toe sub 414, to close the porttherein.

To achieve sequential setting, the packers, such as the packers of FIGS.3 and 4, may each include mechanisms: with receivers that receive uniqueoperating signals to set only when signaled; timers; and/or delaysetting mechanisms, such as metering devices, etc. Many such options arelisted herein below.

To close a toe sub, such as the toe sub 414 of FIG. 4, after thepackers, there can be various options as well, such as those noted aboveand those described in more detail below. The easiest option is likelyto include the use of a timer for the toe sub, which is set to onlyclose the toe sub after the last packer has set. In particular, the toesub may be electronic with a timer controlling closing of a valve forthe toe sub. The timer may be set to have a delay time longer than anydelay time for the packers 400 a to 400 c. The timer may be started atsurface or from the same signal received by the packers. Of course, ifdesired, the toe sub can be closed in other, more manual ways. Someoptions include hydraulic closing, closing by dropping a ball,mechanically with wireline or another work string.

For example, a method where the timing of the setting of the annularpressure responsive packers is sequential and where lower packers areset first, may be accomplished by providing each packer that is to besequentially set with a unique triggering signal, such that one packer,for example, the lowermost unset pressure responsive packer, istriggered uniquely of the packers above it. Alternately or in addition,timers may be used to trigger the sequential packer setting so thatpackers are not set uphole before a packer therebelow can respond toannular pressure. Alternately or in addition, a delay setting mechanismcan be provided on packers uphole of a packer whose operation isresponsive to annular pressure such that while the packers may betriggered at the same time, the setting of some packers is delayedbeyond the setting of other, lower packers. The delay setting mechanismmay actually be a timer.

For example, to avoid problems of premature setting or problems ofpressure isolation (caused by setting of some packers uphole beforeother packers downhole can respond to annular pressure, such ashydrostatic pressure or an annular fluid conveyed signal to set), adelay setting mechanism may be employed to delay stroking for a periodafter it is triggered. A delay, for example, may be useful in a stringwhere a plurality of packers is to be set by pressuring up the annulus.The delay may allow all packers to reach full setting pressure (forexample, just below fracturing pressure), prior to the packers actuallysetting. Such a system can include a triggering device, a settingmechanism responsive to a driver and a delay mechanism to allow thepacker to be triggered but actually delay the final setting of thepacker.

A mechanism to delay the setting of packers can be configured to actafter triggering to resist movement of the packer setting mechanism toits fully set position until after a selected time has lapsed. Thatselected time is longer than the setting mechanism would take to move tothe set position if the delay mechanism was not employed.

For example, in a packer where the packer setting mechanism is actuatedto begin the setting process by a pressure responsive triggeringmechanism, the delay mechanism may be configured to act after actuationby a pressure trigger to delay final setting of the packers, until aftera selected time has lapsed. In one embodiment, the delay mechanism mayinclude a hydraulic chamber that meters movement of the hydraulic fluidtherein to gradually allow a release of a hydraulic fluid. For example,while the setting cylinder can move toward the open position, it isslowed in that movement by the resistance exerted by a delay meteringhydraulic chamber between a moveable part of the closure and anotherfixed part of the closure system. For example, the moveable part maycarry a valved piston that moves through the hydraulic chamber as theclosure is opened. The valved piston slows movement of the moveable partcorresponding to the rate at which the hydraulic fluid in the chambermay pass through the valve's fluid orifice. According to one embodiment,the delay mechanism is adjustable to control the degree of resistanceimparted thereby. For example in an embodiment, employing a hydraulicchamber, the viscosity of the hydraulic fluid and/or the size of thevalve orifice can be selected, to control the metering effect of themechanism.

The delay system may work with a driver that provides the energy to movethe closure to the open position, after it is actuated. The driver mayinclude one or more of a motor, a biasing member such as a spring or apressure charge (i.e. a nitrogen chamber charge or an atmosphericpressure chamber), differential pressures, etc. While the driver may becapable of applying a force to rapidly move the setting cylinder, thedelay mechanism resists and therefore slows such movement. A driver maypermit the setting cylinder to be moved without maintaining the originalpressure drive that initiated the movement. For example, if the triggeris by pressuring up the annulus, the pressure may be dissipated but thedriver continues to apply a driving force to the setting cylinder. Inone embodiment, the driver is selected to operate apart from thetrigger. For example, the driver may be a biasing member that generatesor stores energy that can only be dissipated after the setting cylinderis actuated to begin opening.

The above-noted reference to use of a delay device is with respect to apressure driven trigger. However, it is to be understood that the delaydevice may operate with other triggers, such as those employingsignaling apart from annular pressure signaling, as described in greaterdetail herein below.

While annular pressure drive may be convenient, the porosity of someformations may render it difficult to reliably pressure up the annulus.As such, stroking triggers may include other mechanisms that can beoperated while hydrostatic pressure remains unmodified such that thepacker can be effectively triggered even in boreholes containing openhole sections where it may be advisable to avoid pressuring up theannulus.

In particular, signals other than pressuring up the annulus could beinitiated from surface, such as those employing sound frequency, a radiosignal, a pressure pulse, a vibrational shock wave, etc., that aresensed by the triggering mechanism and cause the driver to set thepacker. The signals could be conveyed through the annulus or through thetubing string.

A pressure pulse could be communicated through the string inner diameterto be sensed by a strain gauge of the triggering mechanism. The straingauge senses the slight mandrel expansion generated by the pressurepulse. Alternately, the triggering mechanism may include a pressuresensitive button in the inner diameter of the mandrel that is responsiveto the pressure pulse and communicates to the triggering mechanism. Ofcourse, any port through which fluid may pass from the mandrel at thepacker should be avoided.

A sound/vibration shock wave, sometimes termed a ping, may be generatedfrom surface or as a result of a surface signal that communicatesthrough the material of the string to a sensor of the triggeringmechanism. For example, a shock wave can be generated by a mechanicalstrike applied to the liner at surface.

According to another embodiment, the triggering mechanism comprises atemperature responsive mechanism. For example, the triggering mechanismexhibits a different thermal contraction and expansion characteristic,so that when the tool assembly heats up, it expands to catch the triggermechanism, and once it cools back down, the packer activates an externalport and allows the atmospheric over hydraulic chamber to stroke andpack off the packing elements. The temperature fluctuations can bedriven from surface to drive the thermal cycling of the temperatureresponsive mechanisms. One possible embodiment operates in response to atemperature change in the well bore to allow the driver, such as amechanism configured to act against an atmospheric chamber to set thepacking element. For example, an expandable piece of metal could bebuilt into the cylinder and the expandable piece of metal can expand orcontract under temperature applications. In one embodiment, the metalpiece expands and lengthens along with the rest of the packer whenheated, but when cooled down, it would contract more than the othercomponents to thereby set the packer. For example, all packer componentsmay expand approximately the same distance or coefficient as the systemheats up when run down hole but when cool down begins, the mechanismsets up the packer. In normal wellbore operations, wellbore temperaturesof 100 degrees F. or to 150 degrees F. are typically encountered, andsome sites can reach around 300 degrees F. Once the liner is in place,the system could be treated to a cool down operation. Cool down of theliner may be achieved during pumping operations, such as during acirculating operation or while fracing the well. In either case, afterall the parts including the packer, the mandrel and the expandable metalpiece are heated, cooling can set the packer, such as by shifting thestroking cylinder to the open position.

Yet another embodiment employs a triggering mechanism with a timer,which can be set to trigger the packer at a particular time to expandthe packing elements. For example, an electronic timer may beincorporated into the packer and may be configured to trigger the packerto set after a particular delay. For example, based on the expected timefor installation of the string, a time may be selected (i.e. 24 to 48hours after the system is installed) after which the mechanism activatesthe setting mechanism to set. If the packers are to be set sequentially(i.e. one at a time), the timer for each packer may have a differentselected time. For example, a packer to set first such as packer 400 cmay have its timer configured with a shorter time than the timer forpacker 400 a, while the timer for packer 400 b has a configuration toset at some time in between. The timers for the packers may be turned onbefore running the tubing string with the packer systems into the well.

In another embodiment, timers may be used to delay the actual settingafter triggering. For example, a packer may be signaled to set, but atimer may delay the actual setting. As such, the timers for the packersmay not actually be turned on before running the packer system into thewell, but may later be turned on and then the packers will set insequence according to the individual time for each packer.

In another embodiment, the trigger may be responsive to an activatingtool, such as a drop bar or plug, such as a ball or dart, released by orfrom surface and passed through the mandrel of the packer. The tool mayemit a signal picked up by the triggering mechanism such as, forexample, a radio frequency signal emitter, an RF ID tag, or the likewhich would be carried on a pump down or dropped tool and a sensor, suchas a radio frequency sensor, can sense the tag and communicate to othercomponents of the triggering mechanism which in turn cause the driver toact on the packer setting mechanism to set the packing elements. Forexample, the sensor may activate electronics of the triggering mechanismwhich in turn opens a port or detonates a charge or causes a hydrauliccylinder to stroke and expand the packer. Such a system may require abattery pack to power the sensor and electronics.

For example, reference is next made to FIGS. 2(a) to 2(f), which showanother embodiment of a wellbore packer. This packer has a driver basedon annular pressure and a triggering mechanism responsive to a signalcommunicated from surface, which in this embodiment is a signalcommunicated via a tool conveyed through the tubing string to thepacker.

The wellbore packer is indicated generally by reference 200 and includesa packing element 220 on a mandrel 210, a hydraulic chamber 246 openablevia a conduit 286 to a chamber 244 that is open to annular pressure, anatmospheric chamber 247, a piston 260, a fixed stop ring 250, acompressing ring 252 and seals 270.

The wellbore packer further includes a magnetic activation mechanism 280(which is a triggering mechanism) comprising a magnetic switch 282. Themagnetic switch 282 is operatively coupled to a hole opener 284, such asa valve, which is operatively coupled to conduit 286 between the chamber244 and chamber 246. As shown, the magnetic activation mechanism 280also includes a battery 287. The hole opener 284 in a closed positionprevents the fluid pressure from being communicated from chamber 244 tochamber 246, as indicated by arrow A in FIG. 2(b). In response toactuation by the magnetic switch 282, the hole opener 284 moves to anopen position and allows fluid to flow from the chamber 244 into chamber246 as indicated by arrow B in FIG. 2(e). According to an embodiment,the battery 287 is operatively coupled to the hole opener 284 andenergizes the hole opener 284 to reconfigure from the closed position tothe open position. The annular fluid pressurizes the chamber 246 andcreates a pressure differential against atmospheric chamber 247 to movethe piston 260 in the direction of arrow C (FIG. 2(e)) which moves thecompressing ring 252 against the packing element 220 and compresses thepacking element against the fixed stop ring 250, as shown in FIG. 2(f).In this position, the packing element 220 is expanded outwardly to fillthe annulus and seal against the wall 212 of the wellbore. Slips (notshown) may also be driven outwardly by this compressive force.

The magnetic switch 282 is activated by exposure to a magnetic field.According to an embodiment, a tool is passed through the mandrelconfigured with a magnetic component that emits a magnetic field andactivates the magnetic switch 282 when moved in the proximity of theswitch 282. For example, a tool such as a ball or dart, indicatedgenerally by reference 290 in FIG. 2(c), is configured with a magneticcomponent capable of activating the magnetic switch 282. The dart 290 isbrought, by dropping, pumping, etc. through the tubing string innerdiameter ID, into proximity with the magnetic switch 282 and magneticswitch 282 is actuated by the magnetic field emitted from the dart 290.Then, as described above, the magnetic switch 282 actuates the holeopener 284, the chamber 246 is pressurized by fluid from the annulus andthe piston 260 is driven in the direction of arrow C (FIG. 2(e)) tocompress and outwardly expand the packing element 220 (i.e. “set” thepacking element 220) as illustrated in FIG. 2(f).

In one embodiment, hole opener 284 may operate in response to powerbeing applied thereto. For example, when the magnetic field is appliedto switch 282, the switch completes a circuit, for example, throughcontacts that become closed such that power can be provided from battery287 to hole opener 284, to cause the hole opener to open.

As noted above, the packer setting operation may include a delaymechanism wherein there is a delay between the packer being triggeredand the packer actually setting. In the illustrated embodiment of FIG.2, for example, a delay mechanism such as timer 292 (FIG. 2(d)) mayoperate delay operation of hole opener 284 to open fluid communicationto chamber 246 for a period of time after plug 290 actually activatesswitch 282.

The above-noted packer is an example of a packer that can be setemploying hydrostatic pressure, since the atmospheric chamber isisolated and can be selected to be less than hydrostatic. Thus thepacker is useful even in open hole conditions such as where the porosityof the formation may render it difficult to reliably pressure up theannulus.

Packer 200 is a no-port packer since there is no port through mandrel210 for communicating tubing string pressure from the inner diameter IDto the packer setting mechanism for initial setting of the packer. Inother words, at least while setting the packer, tubing string pressureis isolated from the packer setting mechanism.

Packer 200, as disclosed, may therefore be set initially by annularpressure. However, packer 200 may be employed on a string intended forwellbore treatment and may, therefore, be installed on a string with afrac port 298 adjacent the packer. Frac port 298 may be offset axiallyalong the tubing string in which the packer is installed. Frac port 298may be normally closed by a closure, such as a sleeve 299. However, thefrac port can be opened to communicate treatment fluids into annulus 213to treat the formation at wall 212.

In such an embodiment, packer 200 is initially set while tubing pressureis isolated from the setting mechanism, the packer may have its settingforce increased when frac pressures are applied through port 298. Inparticular, while frac port 298 is normally closed, as during run in,the frac port can be opened by moving sleeve 299, for example aftersetting the packer, to permit tubing string pressure to be communicatedinto the annular area 213. For example, the packers disclosed herein maybe useful in frac operations wherein after the packer is set (FIG. 2(f))to create a seal and isolate annular area 213 from an annular area 213 aon the other side of the packing element 220, a pressure well abovehydrostatic may be introduced to the annulus 213 between the packer andwellbore bore wall with the intention to frac, and therefore break down,the formation at wall 212. By placing the pressure communication port,in this case conduit 286, in a position where frac pressure iscommunicated to it from annulus 213, pressures much greater than annularhydrostatic, which was used to set the packer, is communicated tochamber 246 and will act against chamber 247 to further compress packingelement 220. As such, when annulus 213 is fraced, the packer's settingforce will be increased.

Frac pressure can only be employed to increase the setting pressure ifthe packer has a piston exposed to frac pressure, as shown in FIG. 2(f).For example, in an embodiment such as that of FIG. 1, packing elements120 a, 120 b, when set, create a pressure isolated wellbore areatherebetween to which frac pressure will not be communicated. If it wasdesired to provide the packer of FIG. 1 with a setting mechanismresponsive to annular frac pressures after initial setting, a pressureresponsive piston open to annular pressure could be provided adjacentring 150 a and/or ring 150 b.

It will be appreciated that according to the port-less packerconfiguration as described above, the packer setting is initiatedthrough application of energy supplied by any of various drivers and atriggering mechanism, to cause setting of the packer when required. Eventhough there is a frac port 298, there is no port through the mandrelthrough which initial packer communication, for example settingpressure, is communicated from the inner diameter to the packermechanism. Thus the packer is a port-less packer. Once the trigger isactivated, the driver energy is communicated to the setting mechanismwhich, then in turn, mechanically sets the packer. As described above, anumber of triggering mechanisms can be utilized as described above,including thermal couplings, electronics, a timing mechanism, a radiofrequency mechanism, etc.

In a method, the packer including its packing components (elements,driver, etc.) and a no-port or port-less mandrel, is installed in atubing string, the string is run into a borehole to a selected positionin the borehole, the packer is triggered (i.e. as described above) to bedriven to expand and seal against the borehole wall to create a seal inan annulus between the string and the borehole wall. Some considerationmay be given to borehole conditions when selecting the triggeringmechanism. According to an exemplary application, the borehole comprisesan open hole section, and the triggering mechanism selected is amechanism suitable for an open hole application, i.e. a triggeringmechanism that is operated without requiring conditions that wouldhinder the formation exposed in an open hole wellbore. According toanother aspect, after initial setting, frac pressure is communicated toa setting mechanism to increase the setting force for the packer.

The previous description of the disclosed embodiments is provided toenable any person skilled in the art to make or use the presentinvention. Various modifications to those embodiments will be readilyapparent to those skilled in the art, and the generic principles definedherein may be applied to other embodiments without departing from thespirit or scope of the invention. Thus, the present invention is notintended to be limited to the embodiments shown herein, but is to beaccorded the full scope consistent with the claims, wherein reference toan element in the singular, such as by use of the article “a” or “an” isnot intended to mean “one and only one” unless specifically so stated,but rather “one or more”. All structural and functional equivalents tothe elements of the various embodiments described throughout thedisclosure that are known or later come to be known to those of ordinaryskill in the art are intended to be encompassed by the elements of theclaims. Moreover, nothing disclosed herein is intended to be dedicatedto the public regardless of whether such disclosure is explicitlyrecited in the claims. No claim element is to be construed under theprovisions of 35 USC 112, sixth paragraph, unless the element isexpressly recited using the phrase “means for” or “step for”.

What is claimed is:
 1. A method for setting a plurality of packers on awellbore string, the method comprising: operating a first wellborepacker by exposing a mechanism of the first wellbore packer to annularpressure; and delaying the setting of a second wellbore packer that isaxially spaced along the wellbore string from the first wellbore packeruntil after operating the first wellbore packer.
 2. The method of claim1 wherein operating includes at least one of triggering and setting. 3.The method of claim 1 wherein delaying includes triggering the secondwellbore packer only after operating the first wellbore packer.
 4. Themethod of claim 1 wherein delaying includes awaiting the expiration of atimer to ensure that operating the first packer proceeds before settingthe second packer.
 5. The method of claim 1 wherein delaying includesoperating a delay mechanism after triggering.
 6. An apparatus for fluidtreatment in a wellbore, the apparatus comprising: a tubing stringhaving a long axis and including a wall portion defining an inner boretherein; a first packer operable to seal about the tubing string andmounted on the tubing string; a second packer operable to seal about thetubing string and mounted on the tubing string in a position axiallyoffset along the tubing string from the first packer; and a packersetting mechanism for selectively operating sequentially the firstpacker and the second packer toward setting.
 7. The apparatus of claim 6wherein the packer setting mechanism comprises a hydraulically actuatedmechanism.
 8. The apparatus of claim 6 wherein the packer settingmechanism is operable in response to fluid pressure communicated to thesetting mechanism from outside the tubing string.
 9. The apparatus ofclaim 6 wherein the packer setting mechanism is operable in response toannular fluid pressure.
 10. The apparatus of claim 6 wherein the packersetting mechanism is operable in response to hydrostatic pressure. 11.The apparatus of claim 6 wherein the packer setting mechanism isoperable in response to a signal conveyed through the annular fluid. 12.The apparatus of claim 6 wherein the packer setting mechanism is forselectively triggering at least one of the first packer and the secondpacker to set.
 13. The apparatus of claim 6 wherein the packer settingmechanism is for selectively setting at least one of the first packerand the second packer.
 14. A method for securing a tubing string in awellbore, the method comprising: running a tubing string into thewellbore, wherein the tubing string includes a long axis, a wall portiondefining an inner bore; a first packer operable to seal about the tubingstring and mounted on the tubing string; a second packer operable toseal about the tubing string and mounted on the tubing string in aposition axially offset along the tubing string from the first packer;positioning the tubing string in the wellbore forming an annulus betweenthe tubing string and a wall of the wellbore; and selectively operatingthe first packer and the second packer sequentially by application ofannular fluid pressure.
 15. The method of claim 14 wherein selectivelyoperating includes triggering a packer to set.
 16. The method of claim14 wherein selectively operating includes setting a packer.
 17. Themethod of claim 14 wherein the first packer is downhole of the secondpacker and annular fluid pressure is hydrostatic pressure andselectively operating includes operating the first packer in response tohydrostatic pressure before setting the second packer.
 18. The method ofclaim 14 wherein selectively operating includes conveying a pressuresignal from surface to the first packer and the second packer.
 19. Themethod of claim 18 wherein conveying a pressure signal includesincreasing the annular fluid pressure and/or conveying a pressure pulse.20. The method of claim 18 wherein the pressure signal is conveyeddownwardly through the annulus.
 21. The method of claim 20 wherein thefirst packer is downhole of the second packer and selectively operatingincludes operating the first packer in response to the pressure signalbefore setting the second packer.
 22. The method of claim 18 wherein thepressure signal is conveyed through the inner bore and upwardly throughthe annulus.
 23. The method of claim 22 wherein the first packer isdownhole of the second packer and selectively operating includesoperating the second packer in response to the pressure signal beforesetting the first packer.
 24. The method of claim 14 wherein afteroperating, the first packer and the second packer create therebetween afirst annular wellbore segment substantially isolated from otherportions of the annulus.